1. Field of the Disclosure
Embodiments disclosed herein relate generally to drill strings for drilling concentric wellbores. More specifically, embodiments disclosed herein relate to drilling systems for drilling substantially vertical wellbores and/or concentric tangential sections of directional wellbores.
2. Background Art
Subterranean drilling operations are often performed to locate (exploration) or to retrieve (production) subterranean hydrocarbon deposits. Most of these operations include an offshore or land-based drilling rig to drive a plurality of interconnected drill pipes known as a drill string. Large motors at the surface of the drilling rig may apply torque and rotation to the drill string, and the weight of the drill string components provides downward axial force. At the distal end of the drill string, a collection of drilling equipment known to one of ordinary skill in the art as a bottom hole assembly (“BHA”), is mounted. Typically, the BHA may include one or more of a drill bit, a drill collar, a stabilizer, a reamer, a mud motor, a rotary steering tool, measurement-while-drilling sensors, and any other device useful in subterranean drilling.
While most drilling operations begin as vertical drilling operations, often the borehole drilled does not maintain a vertical trajectory along its entire path. Often, changes in the subterranean formation will dictate changes in trajectory, as the BHA has natural tendency to follow the path of least resistance. For example, if a pocket of softer, easier to drill, formation is encountered, the BHA and attached drill string will naturally deflect and proceed into that softer formation rather than a harder formation. While relatively inflexible at short lengths, drill string and BHA components become somewhat flexible over longer lengths. As borehole trajectory deviation is typically reported as the amount of change in angle (i.e. the “build angle”) over one hundred feet, borehole deviation can be imperceptible to the naked eye. However, over distances of over several thousand feet, borehole deviation may be significant.
Many borehole trajectories today desirably include planned borehole deviations. For example, in formations where the production zone includes a horizontal seam, drilling a single deviated bore horizontally through that seam may offer more effective production than several vertical bores. Furthermore, in some circumstances, it is preferable to drill a single vertical main bore and have several horizontal bores branch off therefrom to fully reach and develop all the hydrocarbon deposits of the formation. Therefore, considerable time and resources have been dedicated to develop and optimize directional drilling capabilities.
Typical directional drilling schemes include various mechanisms and apparatuses in the BHA to selectively divert the drill string from its original trajectory. An early development in the field of directional drilling included the addition of a positive displacement mud motor to the bottom hole assembly. In standard drilling practice, the drill string is rotated from the surface to apply torque to the drill bit below. With a mud motor attached to the bottom hole assembly, torque can be applied to the drill bit therefrom, thereby eliminating the need to rotate the drill string from the surface. Particularly, a positive displacement mud motor is an apparatus to convert the energy of drilling fluid into rotational mechanical energy at the drill bit. Alternatively, a turbine-type mud motor may also be used to convert energy of the high-pressure drilling fluid into rotational mechanical energy. In most drilling operations, fluids known as “drilling muds” or “drilling fluids” are pumped down to the drill bit through a bore of the drill string where the fluids are used to clean, lubricate, and cool the cutting surfaces of the drill bit. After exiting the drill bit, the used drilling fluids return to the surface (carrying suspended formation cuttings) along the annulus formed between the cut borehole and the outer profile of the drill string. A positive displacement mud motor typically uses a helical stator attached to a distal end of the drill string with a corresponding helical rotor engaged therein and connected through the mud motor driveshaft to the remainder of the BHA therebelow. As such, pressurized drilling fluids flowing through the bore of the drill string engage the stator and rotor, thus creating a resultant torque on the rotor which is, in turn, transmitted to the drill bit below.
Therefore, when a mud motor is used, it may not be necessary to rotate the drill string to drill the borehole. Instead, the drill string slides deeper into the wellbore as the bit penetrates the formation. To enable directional drilling with a mud motor, a bent housing is added to the BHA. A bent housing appears to be an ordinary section of the BHA, with the exception that a low angle bend is incorporated therein. As such, the bent housing may be a separate component attached above the mud motor (i.e. a bent sub), or may be a portion of the motor housing itself. Using various measurement devices in the BHA, a drilling operator at the surface is able to determine which direction the bend in the bent housing is oriented. The drilling operator then rotates the drill string until the bend is in the direction of a desired deviated trajectory and the drill string rotation is stopped. The drilling operator then activates the mud motor and the deviated borehole is drilled, with the drill string advancing without rotation into the borehole (i.e. sliding) behind the BHA, using only the mud motor to drive the drill bit. When the desired direction change is complete, the drilling operator rotates the entire drill string continuously so that the directional tendencies of the bent housing are eliminated so that the drill bit may drill a substantially straight trajectory. When a change of trajectory is again desired, the continuous drill string rotation is stopped, the BHA is again oriented in the desired direction, and drilling is resumed by sliding the BHA.
One drawback of directional drilling with a mud motor and a bent housing includes repeatedly transitioning between sliding and rotating the drill string, thereby affecting the gage of the hole, lateral loading of the bit, and hole quality. Rotation of a bent housing or bent sub in the hole creates eccentric motion at the bit and in the BHA, thereby causing excessive bit wear and stress on other BHA components as they are rotated through this concentric motion. When the drill string is advancing by sliding, the lateral loading on the bit is reduced. The eccentric motion caused by rotation of the bent housing also causes the bit to drill an overgaged hole, that is, a hole with a diameter larger than the diameter of the drill bit. Thus, combinations of in-gage holes formed during drilling while sliding and overgaged holes formed during drilling while rotating result in ledges in the formations, or cutting catchment areas, that present difficulties when pulling the drilling assembly out of the hole or putting the drilling assembly back in the hole. Further, as the drill string advances, a component of the BHA may “stick” in the formation. Weight build-up on the component that is sticking causes the component to be released or “slip” and move forward. Oftentimes, this “stick-slip” reaction may cause shock damage to the bit and other BHA components.
Another drawback of directional drilling with a mud motor and a bent housing arises when the drill string rotation is stopped and forward progress of the BHA continues with the positive displacement mud motor. During these periods, the drill string slides further into the borehole as it is drilled and does not enjoy the benefit of rotation to prevent it from sticking in the formation. Particularly, such operations carry an increased risk that the drill string will become stuck in the borehole and will require a costly fishing operation to retrieve the drill string and BHA. Once the drill string and BHA is fished out, the apparatus is again run into the borehole where sticking may again become a problem if the borehole is to be deviated again and the drill string rotation stopped. Furthermore, another drawback to drilling without rotation is that the effective coefficient of friction is higher, making it more difficult to advance the drill string into the wellbore. This results in a lower rate of penetration than when rotating, and can reduce the overall “reach”, or extent to which the wellbore can be drilled horizontally from the drill rig.
In recent years, in an effort to combat issues associated with drilling without rotation, rotary steerable systems (“RSS”) have been developed. In a rotary steerable system, the BHA trajectory is deflected while the drill string continues to rotate. As such, rotary steerable systems are generally divided into two types, push-the-bit systems and point-the-bit systems. In a push-the-bit RSS, a group of expandable thrust pads extend laterally from the BHA to thrust and bias the drill string into a desired trajectory. An example of one such system is described in U.S. Pat. No. 5,168,941. In order for this to occur while the drill string is rotated, the expandable thrusters extend from what is known as a geostationary portion of the drilling assembly. Geostationary components do not rotate relative to the formation while the remainder of the drill string is rotated. While the geostationary portion remains in a substantially consistent orientation, the operator at the surface may direct the remainder of the BHA into a desired trajectory relative to the position of the geostationary portion with the expandable thrusters. An alternative push-the-bit rotary steering system is described in U.S. Pat. No. 5,520,255, in which lateral thrust pads are mounted on a body which is connected to and rotates at the same speed as that of the rest of the BHA and drill string. The pads are cyclically driven, controlled by a control module with a geostationary reference, to produce a net lateral thrust which is substantially in the desired direction.
In contrast, a point-the-bit RSS includes an articulated orientation unit within the assembly to “point” the remainder of the BHA into a desired trajectory. Examples of such a system are described in U.S. Pat. Nos. 6,092,610 and 5,875,859. As with a push-the-bit RSS, the orientation unit of the point-the-bit system is either located on a geostationary collar or has either a mechanical or electronic geostationary reference plane, so that the drilling operator knows which direction the BHA trajectory will follow. Instead of a group of laterally extendable thrusters, a point-the-bit RSS typically includes hydraulic or mechanical actuators to direct the articulated orientation unit into the desired trajectory. While a variety of deflection mechanisms exist, what is common to all point-the-bit systems is that they create a deflection angle between the lower, or output, end of the system with respect to the axis of the rest of the BHA. While point-the-bit and push-the-bit systems are described in reference to their ability to deflect the BHA without stopping the rotation of the drill string, it should be understood that they may nonetheless include positive displacement mud motors or turbine motors to enhance the rotational speed applied to the drill bit.
Steerable motors having a drilling or mud motor with a fixed bend in a housing thereof that creates a side force on the drill bit and one or more stabilizers to position and guide the drill bit in the borehole are generally considered to be the first systems to allow predictable directional drilling. However, the compound drilling path is sometimes not smooth enough to avoid problems with completion of the well. Also, rotating the bent assembly produces an undulated well with changing diameter, which may lead to a rough well profile and hole spiraling which subsequently might require time consuming reaming operations. Another limitation with steerable motors is the need to stop rotation for the directional drilling section of the wellbore, which can result in poor hole cleaning and a higher equivalent circulating density at the wellbore bottom. This may increase the frictional forces, which makes it more difficult to move the drill bit forward or downhole. Further, control of the tool face orientation of the motor may be more difficult.
To overcome the above-noted difficulties with steerable drilling motor assemblies lead to the development of so called “self-controlled” or active drilling systems. Such systems generally have some capability to follow a planned or predetermined drilling path and to correct for deviations from the planned path. These systems, however, enable faster, and to a varying degree, a more direct and tailored response to potential deviation for directional drilling. Such systems can change the direction behavior downhole, thereby reducing dog leg severity.
A straight hole drilling device (SDD) is often used in drilling vertical holes. A SDD typically includes a straight drilling motor with a plurality of steering ribs, usually two opposite ribs each in orthogonal planes on a bearing assembly near the drill bit. The ribs may be hardfaced or may include tungsten carbide insert (TCI) inlays and are typically configured to sit flush with the hole wall. Such configuration of the ribs may cause drag as the drilling assembly moves downward in the wellbore and may catch or “hang-up” on the formation.
In recent years, square motor housings have been coupled to the drill string for steering and stabilization of the BHA in forming vertical wellbores. The four edges that form the square motor are in substantially constant contact with the wall of the wellbore as the BHA moves down the wellbore. Thus, the square motor provides rigidity of the BHA, thereby maintaining the vertical trajectory of the drill string and reducing the deviation of the drill string due to, for example, formation changes. The square motor, however, produces a lot of friction, and therefore drag, due to the area of contact between the length of the four edges of the square motor and the wall of the formation. These motors also tend to be very noisy while moving the drill string and motor downhole.
Deviations from the vertical are measured by two orthogonally mounted inclination sensors. Either one or two ribs may be actuated to direct the drill bit back onto the vertical course. Valves and electronics, usually mounted above the drilling motor, control the actuation of the ribs. Mud pulse or other telemetry systems are used to transmit inclination signals to the surface. Lateral deviation of boreholes from the planned course (radial displacement) achieved with such SDD systems has been nearly two orders of magnitude smaller than with conventional assemblies. SDD systems have been used to form narrow cluster boreholes and less tortuous boreholes, thereby reducing or eliminating reaming requirements.
A multi-point drilling assembly with a stabilized motor is also known in the art. The multi-point drilling assembly includes a set of reamer cutters incorporated in a bit box which acts as a roller bearing, guiding the drill bit. Stabilizers on the bearing assembly and the stator, also known as the power section, reduce deviation of the drill sting while drilling. The reamer cutters also act to cut the wellbore once the drill bit starts to wear, thereby reducing the amount of undergauged hole. One example of such an assembly is provided by Wenzel Downhole Tools (Oklahoma City, Okla.).
Automated drilling systems having ribs mounted on non-rotating sleeves near the drill bit, wherein each rib may be individually actuated, are known in the art. For example, AutoTrak®, by Baker Hughes Incorporated (Houston, Tex.), has three hydraulically-operated stabilizer ribs mounted on a non-rotating sleeve. Integrated formation evaluation sensors allow steering based on directional parameters and reservoir changes, thereby guiding the bit in the desired direction. A drilling motor may be used to drive the entire assembly, thereby providing more power to the bit. The ribs may be integrated into the bearing assembly of the drilling motor.
Automated drilling systems and rotary steerable systems typically include equipment that is expensive to manufacture and operate. The cost of running an automated drilling system or a rotary steerable system may cost any where from $25,000/day to $40,000/day.
Accordingly, there exists a need for a more cost efficient drilling system that drills a concentric wellbore along a vertical trajectory. Additionally, there exists a need for a more cost efficient drilling system that drills a concentric wellbore along a deviate trajectory. Further, there exists a need for drilling system that minimizes the tortuousity of wellbore and reduces localized dog-leg severity. Still further, there exists a need for a stabilized drilling system with reduced damage to the wall of the wellbore.